What if the current BP spill had been caused by a smaller offshore company like SGY or ATPG?
What future insurance requirements have been discussed for future projects?
I fear that the offshore game will become the sole province of the mega buck players who could foot the bill for a major clean up.
Bob
Spill Impact on Smaller Offshore Drillers
Re: Spill Impact on Smaller Offshore Drillers
Bob;
The deep water exploration already is for the big boys. Yes, if SGY or ATPG had caused this spill they would be done. So would the Hess', Murphy's and Marathon's of the world.
Keep in mind that over 36,000 wells were drilled in the GOM without an incident prior to this. Time and a lot of law suits will tell us who was at fault but my take is that this was a very isolated event. "Stuff" can happen when you encounter pressures like this. I heard the "kick" was at over 30,000 psi. Six months from now the facts will show that the environmental damage is a lot less than what the media is hyping this as now.
I was on a boat that cruised through the area of the Exxon Valdez spill two years after it occured. That spill was twice the size of the oil volume that has entered the GOM from the BP well (so far) and it was in a much smaller body of water. Two years after the spill you could see very little impact on the area, just some small tar balls on the shore line. There was so much more damage to wildlife because the volume of oil released in a smaller area happened very fast. The BP well is 40 miles offshore and most of the oil is disapated before it can reach the coast. Only the real heavy "globs" should reach the shore. Let's hope that BP can get their well plugged soon and we can move on.
Dan
The deep water exploration already is for the big boys. Yes, if SGY or ATPG had caused this spill they would be done. So would the Hess', Murphy's and Marathon's of the world.
Keep in mind that over 36,000 wells were drilled in the GOM without an incident prior to this. Time and a lot of law suits will tell us who was at fault but my take is that this was a very isolated event. "Stuff" can happen when you encounter pressures like this. I heard the "kick" was at over 30,000 psi. Six months from now the facts will show that the environmental damage is a lot less than what the media is hyping this as now.
I was on a boat that cruised through the area of the Exxon Valdez spill two years after it occured. That spill was twice the size of the oil volume that has entered the GOM from the BP well (so far) and it was in a much smaller body of water. Two years after the spill you could see very little impact on the area, just some small tar balls on the shore line. There was so much more damage to wildlife because the volume of oil released in a smaller area happened very fast. The BP well is 40 miles offshore and most of the oil is disapated before it can reach the coast. Only the real heavy "globs" should reach the shore. Let's hope that BP can get their well plugged soon and we can move on.
Dan
Dan Steffens
Energy Prospectus Group
Energy Prospectus Group
-
prince_jake_33
- Posts: 242
- Joined: Mon Apr 26, 2010 2:21 pm
Re: Spill Impact on Smaller Offshore Drillers
Can the casing handle 30000 psig when blowout protector shuts the flow down?
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mdwitte
Re: Spill Impact on Smaller Offshore Drillers
30k psi? seems a little high when the bottom hole pressure was 13k...here is the best "guesstamation" I've come across...
Interesting Post from Yahoo Courtesy of petroglyph
You have to sift through an awful lot of dirt on the Y RIG board to find the diamonds, but I thought this was good. It's put up by a poster named "wildrill"
The following is my theory on what happened on April 20th. I have listed factual information to the best of my knowledge, and base this theory on 33 years of experience working on these rigs, with 16 years working as a consultant worldwide. The contractor (Transocean in this case) typically does not do anything without direction and approval from the operator (BP in this case). I believe that there was nothing wrong with the BOP, or the conduct of the crews prior to the catastrophic failure. If any operator drills a similar well using the same flawed casing and cement program, the same results will be very possible.
The well was drilled to 18,360 ft and final mud weight was 14.0 ppg. The last casing long string was 16 inch and there were 3 drilling liners (13 5/8”, 11 7/8” and 9 7/8”) with 3 liner tops. A 9-7/8” X 7” tapered casing long string was run to TD. The bottom section of casing was cemented with only 51 barrels of light weight cement containing nitrogen, a tricky procedure, especially in these conditions.
The casing seal assembly was set in wellhead and pressure tested from above to 10,000 psi. Reportedly, a lock down ring was not run on the casing hanger. The casing string was pressure tested against the Shear rams, only 16.5 hours after primary cement job. A negative test on the wellhead packoff was performed.
The rig crew was likely lead to believe that the well was successfully cemented, capped and secured. Normally a responsible operator will not remove the primary source of well control (14.0 ppg drilling mud) until such conditions were met. However, the crews were given the order to displace heavy mud from riser with seawater, prior to setting the final cement plugs. They were pumping seawater down the drill string and sending returns overboard to workboat, so there was limited ability to directly detect influx via pit level. This is the fastest way to perform the displacement operation, and the method was likely directed and certainly approved by operator. There was a sudden casing failure during this displacement procedure that allowed the well to unload, with ignition of gas and oil. Evidently, the crew was able to get the diverter closed based on initial photographs, showing flames coming out of diverter lines.
It is likely that pressure built up between the 9 7/8” and 16" casing under the casing hanger, due to gas migration from the pay zone. Based on reported mud weight, the reservoir formation pressure is in excess of 13,000 psi. The pressure building in the cross sectional area below the casing hanger would have increased casing tension and caused casing to collapse and part (rapidly separate) at a connection, probably a joint or two (50’ or 90’) below wellhead. The collapse pressure for 62.8 ppf 9-7/8” casing is +/- 10,300 psi. However, the collapse resistance of casing is considerably reduced in presence of axial stress (i.e. tension). Engineers - see formula from API bulletin 5C3, section 2.1.5 and run the math. The well then came in violently through parted casing and caused the blowout. Without lockdown ring on hanger, the casing hanger and joint(s) were slingshot up into BOP. That would explain why all components of the BOP are unable to seal or shear. The parted casing section remains across all BOP ram cavities and probably all the way up into the riser.
Seven Shortcuts that led to Tragedy:
Shortcut #1: Running a tapered long string rather than a liner with 9-7/8” liner top packer, followed by tieback string and pumping heavy cement all the way to seabed. Perhaps the original permits for this casing program were based on a planned appraisal well, and changed midstream to a producer well, then hastily approved by the complacent or under-staffed MMS. This tragic shortcut may have saved about 1.5 rig days.
Shortcut #2: Insufficient time was used to cure the mud losses prior to cementing the open hole reservoir section, depending instead on using lightweight cement to prevent losses to the formation.
Shortcut #3: The nitrified primary cement job. This is difficult to pull off, even under ideal conditions.
Shortcut #4: Hanger without lock ring may have used due to the previously unplanned long string, and to avoid waiting for hanger with lock ring to be fabricated or prepared.
Shortcut #5: No cement evaluation logs were performed after a job with known high calculated risk (mud losses to formation). This shortcut may have saved 8 hours of rig time.
Shortcut #6: Pressure testing casing less than 24 hours after cement in place can expand the casing before the cement is fully set. This shortcut can “crack” the cement and create a micro annulus which will allow gas migration.
Shortcut #7: Displacing 14 ppg mud from 8000 ft MDRT with 8.7 ppg seawater, less than 20 hours after primary cement is in place. How many tested and proven barriers can you count? I count zero satisfactory barriers. Industry standards dictate that at least two tested (to maximum anticipated pressure) barriers are in place prior to removing the primary source of well control (weighted mud or brine).
The operator and owner of this well ordered and directed all of the shortcuts above. There is no doubt, in my opinion, that this tragedy would not happen on a well operated by Chevron, Exxon Mobil, ConocoPhillips, Shell, Anadarko, Noble Energy, or any other responsible operators familiar to me. Transocean is still the world’s best provider of deepwater rigs and they have very competent crews. The crews on DWH were among the best in the world but they never had a chance against this tragic engineering blunder, and now we have 11 grieving families, and the environmental disaster.
Re: 60 Minutes report on possible Annular rubber observed on shakers -even if the rubber came from one of the two annular elements, the reported quantity is insignificant. These elements can withstand a lot of damage and still seal effectively. I have seen a bucket full of rubber missing from these elements and they still closed and sealed and held pressure as designed.
In my opinion, all lawsuits filed against RIG, HAL, and CAM will be easily re-directed against the operator, when all the facts are established and proven.
http://investorvillage.com/smbd.asp?mb= ... id=9046080
Interesting Post from Yahoo Courtesy of petroglyph
You have to sift through an awful lot of dirt on the Y RIG board to find the diamonds, but I thought this was good. It's put up by a poster named "wildrill"
The following is my theory on what happened on April 20th. I have listed factual information to the best of my knowledge, and base this theory on 33 years of experience working on these rigs, with 16 years working as a consultant worldwide. The contractor (Transocean in this case) typically does not do anything without direction and approval from the operator (BP in this case). I believe that there was nothing wrong with the BOP, or the conduct of the crews prior to the catastrophic failure. If any operator drills a similar well using the same flawed casing and cement program, the same results will be very possible.
The well was drilled to 18,360 ft and final mud weight was 14.0 ppg. The last casing long string was 16 inch and there were 3 drilling liners (13 5/8”, 11 7/8” and 9 7/8”) with 3 liner tops. A 9-7/8” X 7” tapered casing long string was run to TD. The bottom section of casing was cemented with only 51 barrels of light weight cement containing nitrogen, a tricky procedure, especially in these conditions.
The casing seal assembly was set in wellhead and pressure tested from above to 10,000 psi. Reportedly, a lock down ring was not run on the casing hanger. The casing string was pressure tested against the Shear rams, only 16.5 hours after primary cement job. A negative test on the wellhead packoff was performed.
The rig crew was likely lead to believe that the well was successfully cemented, capped and secured. Normally a responsible operator will not remove the primary source of well control (14.0 ppg drilling mud) until such conditions were met. However, the crews were given the order to displace heavy mud from riser with seawater, prior to setting the final cement plugs. They were pumping seawater down the drill string and sending returns overboard to workboat, so there was limited ability to directly detect influx via pit level. This is the fastest way to perform the displacement operation, and the method was likely directed and certainly approved by operator. There was a sudden casing failure during this displacement procedure that allowed the well to unload, with ignition of gas and oil. Evidently, the crew was able to get the diverter closed based on initial photographs, showing flames coming out of diverter lines.
It is likely that pressure built up between the 9 7/8” and 16" casing under the casing hanger, due to gas migration from the pay zone. Based on reported mud weight, the reservoir formation pressure is in excess of 13,000 psi. The pressure building in the cross sectional area below the casing hanger would have increased casing tension and caused casing to collapse and part (rapidly separate) at a connection, probably a joint or two (50’ or 90’) below wellhead. The collapse pressure for 62.8 ppf 9-7/8” casing is +/- 10,300 psi. However, the collapse resistance of casing is considerably reduced in presence of axial stress (i.e. tension). Engineers - see formula from API bulletin 5C3, section 2.1.5 and run the math. The well then came in violently through parted casing and caused the blowout. Without lockdown ring on hanger, the casing hanger and joint(s) were slingshot up into BOP. That would explain why all components of the BOP are unable to seal or shear. The parted casing section remains across all BOP ram cavities and probably all the way up into the riser.
Seven Shortcuts that led to Tragedy:
Shortcut #1: Running a tapered long string rather than a liner with 9-7/8” liner top packer, followed by tieback string and pumping heavy cement all the way to seabed. Perhaps the original permits for this casing program were based on a planned appraisal well, and changed midstream to a producer well, then hastily approved by the complacent or under-staffed MMS. This tragic shortcut may have saved about 1.5 rig days.
Shortcut #2: Insufficient time was used to cure the mud losses prior to cementing the open hole reservoir section, depending instead on using lightweight cement to prevent losses to the formation.
Shortcut #3: The nitrified primary cement job. This is difficult to pull off, even under ideal conditions.
Shortcut #4: Hanger without lock ring may have used due to the previously unplanned long string, and to avoid waiting for hanger with lock ring to be fabricated or prepared.
Shortcut #5: No cement evaluation logs were performed after a job with known high calculated risk (mud losses to formation). This shortcut may have saved 8 hours of rig time.
Shortcut #6: Pressure testing casing less than 24 hours after cement in place can expand the casing before the cement is fully set. This shortcut can “crack” the cement and create a micro annulus which will allow gas migration.
Shortcut #7: Displacing 14 ppg mud from 8000 ft MDRT with 8.7 ppg seawater, less than 20 hours after primary cement is in place. How many tested and proven barriers can you count? I count zero satisfactory barriers. Industry standards dictate that at least two tested (to maximum anticipated pressure) barriers are in place prior to removing the primary source of well control (weighted mud or brine).
The operator and owner of this well ordered and directed all of the shortcuts above. There is no doubt, in my opinion, that this tragedy would not happen on a well operated by Chevron, Exxon Mobil, ConocoPhillips, Shell, Anadarko, Noble Energy, or any other responsible operators familiar to me. Transocean is still the world’s best provider of deepwater rigs and they have very competent crews. The crews on DWH were among the best in the world but they never had a chance against this tragic engineering blunder, and now we have 11 grieving families, and the environmental disaster.
Re: 60 Minutes report on possible Annular rubber observed on shakers -even if the rubber came from one of the two annular elements, the reported quantity is insignificant. These elements can withstand a lot of damage and still seal effectively. I have seen a bucket full of rubber missing from these elements and they still closed and sealed and held pressure as designed.
In my opinion, all lawsuits filed against RIG, HAL, and CAM will be easily re-directed against the operator, when all the facts are established and proven.
http://investorvillage.com/smbd.asp?mb= ... id=9046080